Knowledge of the flow rate of fluid in hydrocarbon well boreholes is important for monitoring and controlling fluid movement in the well and reservoir. Typically, in such hydrocarbon wells, the fluid flowing along the borehole includes a hydrocarbon (e.g. oil) and water. Each zone of the reservoir may have a valve to control the fluid inlet from that zone. By monitoring the flow rates of oil and water coming from each zone, the flow rate of oil can be optimised by control of the valves. In this way, the water cut may be minimised for example.
A flow meter installed in piping in a hydrocarbon well borehole is subject to several design restrictions which may not apply to flow meters based on the surface. For instance, a downhole flowmeter should be able to operate relatively maintenance-free, due to the remoteness of its location. The flow meter should be able to cope with non-mixed and mixed flow regimes over a wide range of total flow rate and cut. Furthermore, the flow meter should not be sensitive to its orientation.
It is also often necessary to monitor or analyze the formation rock and the condition of piping and other components within the borehole. Measurements for this determination are usually taken by passing data logging tools along the pipeline. Such tools are dimensioned to pass along standard pipe sizes. Thus a flow meter for use downhole should be adapted to allow the unobstructed passage of logging tools.
In non-mixed flow (such as stratified flow) the oil phase velocity and the water velocity are usually different. The difference in velocity is the phase slip. The volume fraction of water (holdup) must be measured in order to determine the flow rate of water, and similarly for the flow rate of oil. Thus, the determination of flow rate for a two-phase flow can be significantly more complex than for a single phase flow, and usually attempts are made to mix the flow before flow rate measurements are taken.
In so-called “three-phase” flow, gas is present in a mixture of water and oil. The present of gas poses further problems when establishing exact flow-rates and hold-ups. Gas usually has properties significantly different from oil and water, thus limiting the scope of many methods suitable for liquid-only flows.
In many downhole applications, such as drill stem testing (DST), the flow to be measured can range from single-phase, such as oil or gas flow, to multi-phase such as oil/gas/water three-phase flows. In some cases, solid particles may exist in the flow. The inclination of the well may also vary widely, from vertical, through deviated to horizontal. The combination of multi-phase flow with various inclinations leads to complex flow regimes, which should be taking into account when developing a down-hole flow meter.
Under down-hole environment, the pressure of the fluid is likely to be high. Therefore, for an oil well, the percentage of gas in the flow should be much less than that encountered in the application of surface flow metering. Also at down-hole, the density of the gas is high whereas the speed of sound in gas also increases due to the elevated temperature; such a combination leads to a reduced contrast between the acoustic impedance of the liquid phase and that of the gas phase.
A down-hole multi-phase flowmeter needs, ideally, to measure the flow rates of all the phases of interest. Volumetric flow rate of a particular phase can be obtained by measuring directly the velocity and fraction of that phase. Some times a phase velocity may be derived from some other indirect measurements if these are easier to implement than a direct measurement.
For instance, if the oil velocity in a gas/oil flow is difficult to measure directly, whereas it is possible to measure a mixture or homogeneous velocity of the fluid plus the gas fraction and gas velocity, then the liquid velocity can be derived according to:Vh=(1−αg)·Vo+αg·Vg  [1]where Vh is the homogeneous velocity, Vo the oil velocity, Vg the gas velocity and αgthe gas fraction. If one has a slip velocity model, say Vg/Vo=k, where k is known, then the oil velocity may be derived from Eq. 1, even without the measurement of Vg.
One of the general flow metering technologies particularly relevant to this invention is the ultrasonic flow meter based on the transit time measurement principle such as described for example by Doebelin E. O, “Measurement Systems—applications and design”, 4th edition, McGraw-Hill, 1990, Chapter 7, pp. 589-591 [1] or the U.S. Pat. Nos. 4,735,097 (or EP-A-0212470); 4,838,127 or 5,533,408.
There are many versions of such flow meter available commercially. However the basic measurement principle is similar—an acoustic pulse of ultrasonic frequency is transmitted in the fluid, firstly in the direction along the flow and then in the reverse direction against the flow. The pulse propagation times from the transmitter to the receiver are measured for pulses traveling in both directions. These time-of-flight measurements are then combined with the know separation distance between the transmitter and the receiver to produce the flow velocity. The drawback of such a flowmeter is that it is only applicable to near single-phase flows. This is because at ultrasonic frequency, the wavelength in the fluid is short, and the wave is thus seriously attenuated and dispersed in a multi-phase flow by the presence of bubbles/droplets of one flow phase in another.
Another relevant flow metering method is the pressure pulse method described by Gudmundsson and Celius in: Gudmundsson J. S. and Celius H. K, “Gas-Liquid Metering Using Pressure Pulse Technology”, paper SPE56584, presented at the 1999 SPE Annual Technical Conference and Exhibition, Houston, 3-6 October. In their method, a quick-closing valve is used to choke the flow, and the pressure increase due to the water-hammer effect is measured. This pressure change also creates a pressure pulse wave with very low frequency (<10 Hz), which propagates backwards towards the upstream of the flowline. The speed of sound in the flow can be measured from the traveling speed of this propagating wave. The speed of sound can be used to determine the phase fraction, such as gas void fraction, in a two-phase flow through correlations well documented in the literature as cited above.
The magnitude of the pressure change can be combined with the measured speed of sound to produce a mass flow rate measurement for the mixture flow. This method has been used on surface pipes near the wellhead to meter gas/oil flows. The main drawback is the need to choke the flow with a quick closing valve, which is often not permitted for down-hole applications such as the DST.
Kragas et al. described an optical fiber based down-hole flowmeter in: Kragas T. K., Bostick III F. X., Mayeu C., Gysling D. L. and van der Spek A. M., “Down-hole Fiber-Optic Flowmeter: Design, Operating principle, Testing, and Field Installations”, paper SPE 87086, first presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, Tex., 29 September-2 October.
The basic principle of the fiber-based device relies on passive acoustic signal sensing and analysis. First, it used a fiber-optical acoustic sensing array to detect the acoustic signals generated naturally in the flow and measure the speed of such acoustic signal propagating along the borehole. Since these signals are of low frequency (long wavelength) nature, the speed of sound can be used to determine the phase fraction in a two-phase mixture. Second, discontinuous or non-uniform structures in the multi-phase flow produce acoustic signatures that can be detected by the fiber-optical sensor as they pass the sensor. Therefore with two sensors separated by a known distance, the travel velocity of such structures can be determined by, say, a cross-correlation measurement. This cross-correlation velocity is treated as the homogeneous velocity of the flow.
The drawbacks with this flowmeter are: first, the passive acoustic method is not reliable if the flow is nearly single-phase, as it sometimes is in down-hole applications; second, the travel velocity of the non-uniform structures, from our experience in down-hole flow meters, cannot be always equalized to the homogeneous velocity, particularly at low velocities and in highly deviated wells. The cross-correlation based method also will not work in single-phase flows where the non-uniform structures do not exist.
With the known methods and apparatus in view, the present invention proposes to provide a measurement of flow characteristics, such as the homogeneous velocity, in a downhole flow. Ideally the apparatus is non-intrusive in allowing an unrestricted passage of the downhole flow through the apparatus.